In drilling a borehole or wellbore, the borehole can have the same general diameter from the ground surface to total depth (TD). However, most boreholes have an upper section with a relatively large diameter extending from the earth's surface to a first depth point. After the upper section is drilled a tubular steel pipe is located in the upper section. The annulus between the steel pipe and the upper section of the borehole is filled with a liquid cement slurry which subsequently sets or hardens in the annulus and supports the liner in place in the borehole.
After the cementing operation is completed, any cement left in the pipe is usually drilled out. The first steel pipe extending from the earth's surface through the upper section is called "surface casing". Thereafter, another section or depth of borehole with a smaller diameter is drilled to the next desired depth and a steel pipe located in the drilled section of borehole. While the steel pipe can extend from the earth's surface to the total depth (TD) of the borehole, it is also common to hang the upper end of a steel pipe by means of a liner hanger in the lower end of the next above steel pipe. The second and additional lengths of pipe in a borehole are sometimes referred to as "liners".
After hanging a liner in a drilled section of borehole, the liner is cemented in the borehole, i.e. the annulus between the liner and the borehole is filled with liquid cement which thereafter hardens to support the liner and provide a seal with respect to the liner and also with respect to the borehole. Liners are installed in successive drilled depth intervals of a wellbore, each with smaller diameters, and each cemented in place. In most instances where a liner is suspended in a wellbore, there are sections of the casing and of the liner and of adjacent liner sections which are coextensive with another. Figuratively speaking, a wellbore has telescopically arranged tubular members (liners), each cemented in place in the borehole. Between the lower end of an upper liner and the upper end of a lower liner there is an overlapping of the adjacent ends of the upper and lower liners and cement is located in the overlapped sections.
After a liner has been located through an earth strata of interest for production, the well is completed. The earth strata is permeable and contains hydrocarbons under a pore pressure.
In the completion of a well using a compression type production packer, typically a production tubing with the attached packer is lowered into the wellbore and disposed or located in a liner just above the formations containing hydrocarbons. The production packer has an elastomer packer element which is axially compressed to expand radially and seal off the cross-section of the wellbore by virtue of the compressive forces in the packer element. Next, a perforating device is positioned in the liner below the packer at the strata of interest. The perforating device is used to develop perforations through the liner which extend into cemented annulus between the liner and into the earth formations. Thereafter, hydrocarbons from the formations are produced into the wellbore through the perforations and through the production tubing to the earth's surface.
In the production of liquid hydrocarbons, gas is also produced during the life of a production well, gas migration or leakage in the wellbore is a particularly significant problem which can occur where gas migrates along the interfaces of the cement with a liner and a borehole. Any downhole gas leak outside the production system is undesirable and can require a remedial operation to prevent the leak from causing problems to other strata. Downhole gas leaks are commonly due to the presence of a micro-annulus between the cement annulus and the borehole wall and are difficult to prevent. There are also liquid leaks which can be equally troublesome. There are a number of prior art solutions proposed to obtain a tight seal of the cement column with the formation. Heretofore, however, none of these solutions have taken into account the borehole stress and the effect of downhole temperatures changes which occur during the cementing process.
The net effect of a considerable number of wellbore completion and remedial operations where liquids are circulated in the wellbore is to temporarily change the temperatures along the wellbore from its normal in-situ temperature conditions along the wellbore. The in-situ temperature conditions refer to the ambient downhole temperature which is the normal undisturbed temperature. However, the ambient downhole temperature can be higher than in-situ temperatures due to conditions such as steam flooding or production from other zones.
At any given level in a wellbore, the temperature change may be an increase or decrease of the temperature condition relative to the normal in-situ or ambient temperature depending upon the operations conducted.
In a co-pending application Ser. No. 865,188 filed Apr. 9, 1992, and entitled "Borehole Stressed Packer Inflation System", a system is described for use with inflatable packers where temperature effects are considered relative to obtaining a positive seal with an elastomer element in an inflatable packer.
In this application, the system is concerned with obtaining a cement seal of a column of cement between a liner and a borehole wall by taking into account the effect of downhole temperature effects. Downhole temperature effects can be caused by a number of factors, including acidizing, fracturing, steam injection or production from other intervals in a wellbore.
In primary cementing of a liner in a wellbore, heretofore, there also has been no consideration of the resultant final contact sealing force of the cement with the borehole wall after the wellbore resumes its ambient condition. Primary cementing is a complex art and science in which the operator utilizes a cementing composition which is formulated by taking into account the borehole parameters and drilling conditions. The objective of the cementing process is to fill the annulus between the liner and the borehole along the length of the liner with the cement bonding to or sealing with respect to the outer surface of the pipe and with respect to the borehole wall. A cured cement is intended to serve the purpose of supporting the weight of the pipe (anchoring the pipe to the wellbore) and for preventing fluid migration along the pipe or along the borehole wall and to provide structural support for weak or unconsolidated formations. Fluid migration is prevented if bonding of or sealing of the cement occurs with the pipe and with the borehole wall. One of the reasons that cement bonding fails to occur is because of the volumetric contraction of the cement upon setting. Despite all efforts to prevent contraction and efforts to cause expansion, cement tends to separate from a contacting surface. The separation in part can be related to the temperature effects in the borehole as will be discussed hereafter. Another factor in cement bonding is that the wellbore is drilled with a control fluid such as "mud" where a well surface filter cake is formed on permeable sections of the wellbore (to prevent filtrate invasion to the formations). The filter cake is, of course, wet and difficult to bond to cement.
The problem of bonding in primary cementing does not arise in many instances simply because the downhole formation pore pressures of the fluids do not exceed the inherent sealing characteristics of the cement column in place. This is particularly true in situations where a long impermeable interval is located above the production zone. However, where permeable zones are relatively close to one another and/or when pressure treating operations are conducted and/or gas is produced, leakage along the cement interface is more likely to occur.